Method and System for Removing Hydrogen Sulfide from Sour Oil and Sour Water

ABSTRACT

Embodiments of the present invention are generally related to a system and method to remove hydrogen sulfide from sour water and sour oil. In particular, hydrogen sulfide is removed from sour water and sour oil without the need for special chemicals, such as catalyst chemicals, scavenger chemicals, hydrocarbon sources, or a large scale facility. The system and method in the present invention is particularly useful in exploratory oil and gas fields, where large facilities to remove hydrogen sulfide may be inaccessible. The present invention addresses the need for safe and cost effective transport of the deadly neurotoxin. Particular embodiments involve a system and method that can be executed both on a small and large scale to sweeten sour water and sour oil.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent applicationSer. No. 14/185,006, entitled “METHOD AND SYSTEM FOR REMOVING HYDROGENSULFIDE FROM SOUR OIL AND SOUR WATER” filed Feb. 20, 2014, which claimsthe benefit of U.S. Provisional Patent Application 61/768,029, entitled“METHOD AND SYSTEM FOR REMOVING HYDROGEN SULFIDE FROM SOUR OIL AND SOURWATER” filed on Feb. 22, 2013, the entire contents of which areincorporated herein by reference in their entirety for all purposes.

FIELD OF THE INVENTION

Embodiments of the present invention are generally related to a systemand method to remove hydrogen sulfide from sour water and sour oil. Inparticular, hydrogen sulfide is removed from sour water and sour oilwithout the need for special chemicals, such as catalyst chemicals,scavenger chemicals, hydrocarbon sources, or a large scale facility. Thesystem and method in the present invention is particularly useful inexploratory oil and gas fields, where large facilities to removehydrogen sulfide may be inaccessible. The present invention addressesthe need for safe and cost effective transport of the deadly neurotoxin.Particular embodiments involve a system and method that can be executedboth on a small and large scale to sweeten sour water and sour oil.

BACKGROUND OF THE INVENTION

Exploration of gas fields can involve discovery of wells that containsignificant quantities of hydrogen sulfide and other organic andinorganic sulfur compounds. Oil, natural gas, and water with a highconcentration of sulfur compounds such as hydrogen sulfide and sulfurdioxide are referred to as “sour.” Hydrogen sulfide is a colorless,toxic, flammable gas that is responsible for the foul odor of rotteneggs. It often results when bacteria break down organic matter in theabsence of oxygen, such as in swamps, and sewers alongside the processof anaerobic digestion. It also occurs in volcanic gases, natural gasand some well waters. Sour oil and sour water are not only undesirableas sour products are economically useful, they can be extremely toxicand deadly because high levels of sulfur and sulfur byproducts. Forexample, hydrogen sulfide is a highly toxic and extremely deadly gas.The industry considers oil or water containing 100 parts per million(“ppm”) (0.01%) sulfur sour oil and sour water. Although this is theminimum level, oil wells and water can contain higher amounts. Oil andwater can contain hydrogen sulfide up to 300,000 ppm (30%) at theimmediate gas/liquid interphase, the vapor space in a tank or container,and the atmosphere surrounding a spill. At higher concentrations,hydrogen sulfide is toxic and deadly.

As used herein, the term “sour oil” refers to oil containing levels ofhydrogen sulfide in an amount greater than 100 ppm (0.01%). Sour oil canalso mean oil containing 0.5% or more sulfur by weight. The term “sourwater” refers to water containing hydrogen sulfide in an amount greaterthan 100 ppm (0.01%). The terms “sweet,” “sweetened,” and/or“sweetening” mean a product that has low levels of hydrogen sulfide, hashad hydrogen sulfide removed, or the process of removing hydrogensulfide. The term “stripping” means removing hydrogen sulfide from waterand/or oil. The terms “acceptable limits” or “acceptable amounts” or“acceptable levels” refer to the maximum amount of hydrogen sulfideallowed according to any of the pertinent regulations. For example, theEnvironmental Protection Agency (“EPA”) has certain regulationsregarding the concentration of hydrogen sulfide that may be releasedinto the environment. Furthermore, the Occupational Safety and HealthAdministration (“OSHA”) provides certain regulations on the amount ofhydrogen sulfide one may be exposed to without being considered a healthhazard. There may be other regulations that apply, such as stateregulations. The terms “acceptable limits” or “acceptable amounts” or“acceptable levels” can also refer to the maximum amount of hydrogensulfide allowed in oil and/or water in order for a facility to acceptthe materials.

Exploratory and developmental wells with high concentrations of hydrogensulfide, far away from hydrogen sulfide removal facilities present aproblem of transporting the sour water and sour oil. Both liquids mustbe transported by truck, sometimes long distances over public andprivate roads. In most cases, sour water, which is dangerous totransport, will also not be accepted by most re-injection facilities ifit contains more than a trace amount of hydrogen sulfide.

Similarly, sour oil, which is also dangerous to transport, will not beaccepted by most refineries or pipeline hubs, if it contains more than atrace of hydrogen sulfide. If one finds a facility willing to acceptliquids with a high concentration of hydrogen sulfide, odds are they arehundreds of miles away from the exploratory well. A truck accident or asimple leak could endanger the transportation crew, as well as thepublic.

There are other problems downstream in the transportation of sour oil aswell. For example, transport from the exploratory well to a treatmentsite is usually only the first step in the process. The oil typicallyhas an end destination, whether it is another refinery, a distributer,or a consumer. Any contamination by hydrogen sulfide along the way wouldcreate a safety and environmental hazard. One example can be seen intransportation of oil that is obtained through a fracturing or“fracking” process. Oil extracted through the fracking process typicallyis sweet and contains little hydrogen sulfide. This oil has to betransported from the site to its end destination. The transportation canbe hindered, however, if there is an upstream contamination of hydrogensulfide of the shipping vessels or oils with different grades are mixedfor shipping.

Rail shipment of crude oil has become an option for moving oil out ofhigh production areas with little pipeline access. The shipping industryis adversely affected by having to address the shipping of hydrogensulfide. The solution to rail safety issues are typically unanticipatedcosts, including rail car investments or new safety protocols to addressthe shipping of sour oil.

For example, an oil-loading rail terminal in North Dakota may be forcedto shut down its facility unless the amount of hydrogen sulfide in crudeoil delivered to the facility can be reduced. The oil-loading railterminal requested the Federal Energy and Regulatory Commission (FERC)to restrict the amount of hydrogen sulfide in crude deliveries, after alarge concentration of hydrogen sulfide was discovered a tank at anupstream facility. The terminal requested a limit of 5 ppm hydrogensulfide. Another company objected to the request, as it ships crude oilto the terminal. In response, the terminal asserted that without the newlimits to hydrogen sulfide coming to its facility, its employees whostand on top of rail tankers to pump crude could be exposed to harmfulvapors. The terminal further argued that if higher levels were allowedto be delivered to its terminal, other terminals downstream would haveto shut down its rail facility.

Even if the sour water and sour oil is treated to remove hydrogensulfide content through conventional methods of using scavengers orother treating chemicals, facilities will not accept the treated wateror oil if it contains too much of the treatment chemicals. This isespecially problematic with wells containing high levels of hydrogensulfide that require more of the treatment chemicals to remove thehydrogen sulfide concentrations.

Moreover, many regulations are in place regarding the treatment anddisposal of sour oil and sour water. For example, in order to ventundesirable sour water, there has to be less than 10 ppm (0.001%) ofhydrogen sulfide vented into the open air according to OSHA regulations.Burning sour oil quickly reaches the emission limits per site. Forexample, common limits for sulfur emissions are between 100 tons and 250tons of sulfur. In order to achieve these lower concentrations, theindustry has typically used methods involving the use of reducing sulfurcontent using chemical catalysts that remove sulfur. These are typicallyliquid hydrogen sulfide scavengers added to the water or oil to absorbthe hydrogen sulfide and prevent it from becoming vapor. This solutionis feasible and affordable where there is a low concentration ofhydrogen sulfide in the water or oil. Once the gas product of the wellgets much over 5000 ppm (0.05%), the oil and water will contain amountsof hydrogen sulfide such that liquid scavengers become very expensive.With wells approaching or exceeding 10,000 ppm (1%) hydrogen sulfide,the cost of using liquid scavenger on the oil and water products exceedsthe value of the oil itself after transportation costs.

For example, a well with an average of 30,000 ppm (3%) hydrogen sulfidein its gas product, 40,000 ppm (4%) in the vapor space of its watertanks and 60,000 ppm (6%) in the vapor space of its oil tanks mighteasily cost $20 per barrel of water and $40 per barrel of oil to usehydrogen sulfide scavengers to treat those liquids so that they are safefor transportation. Even then, it takes a special refinery to be able toaccept oil such high concentrations of the scavenger materials.

Furthermore, the liquid scavengers appropriate for water and oil arethemselves very noxious chemicals. Workers dealing with these chemicalsmust wear full HAZMAT suits. And, if there is a spill of the scavengerchemicals at any point during transportation, it again poses a threat tothe safety of the public and the transport personnel.

Sour oil and sour water high in hydrogen sulfide is extremely toxic andrapidly deadly. Hydrogen sulfide is lethal if inhaled in concentrationsdown to 1000 ppm (0.1%) in air or water or oil vapor. At lowconcentrations, hydrogen sulfide has a characteristic odor similar tothe smell of rotten eggs. At higher concentrations, the typical rottenegg odor is lost, as hydrogen sulfide can fatigue the sense of smell.

Hydrogen sulfide is a very toxic gas at normal temperatures. It poses avery serious inhalation hazard. There is a large amount of informationon human exposures. However, in most cases, the exposure levels andexposure durations are unknown or crudely estimated. Effects at variousexposure levels are believed to be as follows: 0.001-0.13 ppm—odorthreshold (highly variable); 1-5 ppm—moderately offensive odor, possiblywith nausea, or headaches with prolonged exposure; 20-50 ppm—nose,throat and lung irritation, digestive upset and loss of appetite, senseof smell starts to become “fatigued”, odor cannot be relied upon as awarning of exposure; 100-200 ppm—severe nose, throat and lungirritation, ability to smell odor completely disappears; 250-500ppm—potentially fatal build-up of fluid in the lungs (pulmonary edema)in the absence of central nervous system effects (headache, nausea,dizziness), especially if exposure is prolonged; 500 ppm—severe lungirritation, excitement, headache, dizziness, staggering, sudden collapse(“knockdown”), unconsciousness and death within 4-8 hours, loss ofmemory for period of exposure; 500-1000 ppm—respiratory paralysis,irregular heartbeat, collapse, and death. It is important to note thatthe symptoms of pulmonary edema, such as chest pain and shortness ofbreath, can be delayed for up to 48 hours after exposure.

Prolonged exposure (for several hours or days) to concentrations as lowas 50-100 ppm can cause a runny nose, cough, hoarseness, and shortnessof breath. Prolonged exposure to higher concentrations can producebronchitis, pneumonia and a potentially fatal build-up of fluid in thelungs (pulmonary edema). There are numerous case reports of deaths,especially among workers in the petroleum, sewage treatment, andagricultural industries. Most fatalities have occurred in relativelyconfined spaces (e.g. sewers, sludge tanks, cesspools, or hydrogensulfide collecting in pits or dips on open land or in buildings). Inmany cases, multiple deaths have occurred at a single site. Rescuers,attempting to save an unconscious co-worker, have entered a hazardousand/or confined area without respiratory protection or safety lines.They, in turn, have been overcome by hydrogen sulfide.

Workers who survive a serious short-term hydrogen sulfide exposure mayrecover completely or may experience long-term effects. Nervous systemand respiratory effects have been described in small human populationstudies or case reports. Permanent or persistent nervous system effectshave included fatigue, anxiety, irritability, intellectual decline,reduced attention span, impaired learning and memory, altered sense ofsmell, and motor deficits. Some of the nervous system effects may be dueto a lack of oxygen reaching the brain cells during a severe hydrogensulfide exposure. Respiratory effects have included symptoms (shortnessof breath upon exertion, chest tightness or wheezing) consistent withhypersensitivity of the airways (Reactive Airways Dysfunction);permanent lung damage (pulmonary fibrosis) and significant reductions inresidual volume (one measure of lung function).

Although cyanides are better known to the general public to invokethoughts of deadly poisons and toxicity, hydrogen sulfide are just asdeadly. For example, incidents involving the deadly nature of hydrogensulfide are well documented. One example involved the death of ninepeople in Texas who were killed by gases leaking from an unattendedcarbon dioxide injection system designed to extract oil from a well inTexas. Eight of the victims were in a house 100 yards from the well.

In another example involving transportation of hydrogen sulfide, twoMichigan employees drove a tank truck to a sour oil well tank farm toobtain waste brine. When they failed to get a flow of brine from aground level connection just outside the tank farm dike, they proceededto the brine tank. One employee went to the top of the tank, which was13 feet above the ground. He yelled a warning, but was instantaneouslyovercome by escaping hydrogen sulfide-rich gas. He was later found deadon the platform beside the top of the tank. The other worker waitingnear the top of the stairs was overcome and collapsed before he couldretreat. Fortunately, he fell down the stairway out of the area ofcontamination and regained consciousness. The hatch that had been openedwas upwind of the access platform and about two feet above it. Clearly,it is beneficial to have a simple, economic, and effective way to reducethe level of hydrogen sulfide from materials in order to improve safetyat exploratory sites and safety in the transportation of materials.

In addition to the health hazards due to exposure to hydrogen sulfide,hydrogen sulfide is a flammable gas that creates additionaltransportation hazards. Recently, 47 people died when a freight traintransporting crude oil caught on fire when it wrecked. The compositionis under investigation, as crude oil typically does not explode.Contamination of the shipment with hydrogen sulfide from an upstreamsource is being considered a culprit to why the freight train explodedunexpectedly. Certain embodiments of the present invention address thesafety concerns with shipping oil containing hydrogen sulfide and canprevent contamination of otherwise less hazardous oil.

Other current methods to remove hydrogen sulfide involve the use of usenatural gas to remove sulfur, or use specialized apparatus that useamine to remove sulfur. The majority of processes to sweeten oil involveabsorption of hydrogen sulfide in an amine solution, use of a carbonateprocess, use of solid bed absorbents and physical absorption. Forexample, U.S. Patent Publication No. 2012/0111769 to Hassan et al.(“Hassan”), incorporated in its entirety by reference, describes amethod where the sour oil is subjected to a high shear and at least onedesulfurizing agent wherein the desulfurizing agent is selected from agroup consisting of bases and inorganic salts to produce a high shearstream and separating the sulfur rich product and sweetened oil productfrom the high shear-treated stream. Hassan further describes a systemand a method that use a shearing mechanism in combination with chemicalsor other gases to remove sulfur. According to the Hassan system andmethod, one needs high shear and at least one chemical desulfurizingagent.

U.S. Pat. No. 8,216,520 issued to Choi et al. and Patent PublicationsNos. 2011/0147266, 2009/0173664 and 2011/0315600 also by Choi et al.(collectively “Choi”), all incorporated by reference in their entirety,involves a system, method, and apparatus for upgrading heavy oil. Choidescribes a system and method that involves combining heavy oil with awater feed in a mixing zone to form a heavy oil/water mixture, whereinthe mixture does not exceed 150 degrees Celsius; subjecting the oilwater mixture to ultrasonic waves to create a submicromulsion; pumpingthe submicromulsion using a high pressure pump to increase the pressureto or above the critical pressure of water; and heating thesubmicromulsion between 150 degrees C. and 350 degrees Celsius. Choifurther describes adding a heated oxidant stream to the heavy oil/watermixture wherein the heated oxidant stream is at a temperature andpressure that exceeds the critical temperature and pressure of water;introducing the mixture into a zone essentially free of anexternally-provided catalyst wherein the reaction is subjected toconditions that exceed the supercritical conditions of water such that aportion of hydrocarbons in the reaction mixture undergoing cracking toform an upgraded mixture. Furthermore, the Choi process requiressubjecting the mixture to ultrasonic waves.

The Choi process requires a special apparatus that has a mixing zone tocombine heavy oil with a water feed at a slightly elevated temperatureto create a heavy oil/water mixture, where the mixing zone is anultra-sonic wave generator; a pre-heating zone that is fluidly connectedwith the mixing zone, operable to heat the heavy oil/water mixture to atemperature up to about 350 degrees Celsius; a high pressure pumpingmeans, operable to increase pressure of the heavy/oil water mixture toat least the critical pressure of water; and a reaction zone that isessentially free of an externally provided catalyst and anexternally-provided hydrogen source fluidly connected with thepre-heating zone and able to withstand the temperature of the criticaltemperature of water and being able to withstand the pressure in excessof the critical pressure of water. The result is an upgraded oil withreduced amounts of substances such as sulfur.

The Choi process, although describing a system and method essentiallyfree of external catalysts or external hydrogen to remove compoundsincluding sulfur compounds, requires heating oil and water, mixing thewater with an ultrasonic component, a high pressure system to bring themixture to the critical pressure of water. Choi teaches away from asystem and method that can remove sulfur byproducts, such as hydrogensulfide, from sour oil without complex equipment and a highly controlledenvironment.

U.S. Pat. No. 4,253,298, issued to Blytas et al. (“Blytas”) describes amethod of sour water treatment in which sour water components areremoved from a sour water stream in an electrodialysis step in which thesour water stream becomes the dilute stream. The Blytas process subjectsa sour water stream to an electrodialysis step in which the acidiccomponent and the basic component of the stream migrate from the streamthrough a fixed anion and cation exchange membrane to one or moreconcentrate streams, and steam strip the concentrate streams in order toremove the volatile acidic component and the volatile basic component.Blytas is incorporated by reference in its entirety. This method isgeared toward a pre-process, upstream of an unspecified steam-strippingprocess. It uses electrodialysis which requires complex mechanical andprocess parameters not suitable for field use due to cost andportability. For example, Blytas uses a membrane to remove sourcomponents from water. This is a pre-process treatment and does notaddress hydrogen sulfide vented in the steam process with regard tosafely breathable concentrations. The present invention is devoid of theuse of a membrane to remove hydrogen sulfide from sour water.Furthermore, the present invention does not require a steam-strippingprocess.

Other methods of removing hydrogen sulfide from water involve using ahigh voltage electrooxidation. U.S. Patent Publication No. 2012/0273367,by Themy et al. (“Themy”) removes hydrogen sulfide through the use ofelectrooxidation. Themy is incorporated by reference in its entirety.Hydrogen sulfide is present as the part of hydrocarbon streams typicalof petroleum recovery sources. Accordingly, hydrogen sulfide cancontaminate various water sources and wastewater streams, includingthose from hydraulic fracturing operations. Hydrogen sulfide iscorrosive and renders some steels brittle, leading to sulfide stresscracking, which is a concern in many applications, particularly whenhandling acid gas and sour crude oil in the oil industry. Thus, removalof hydrogen sulfide is desirable in the art. The primary method used inthe art of removing hydrogen sulfide is the Claus process, whichproceeds according to Formula 2H₂S+O₂→2S+2H₂O. Other current technologyavailable to remove hydrogen sulfide includes high pressure oxygenationof hydrogen sulfide solutions and oxidations with ozone and hydrogenperoxide. Therefore, the water purification systems and methods may alsobe useful for removing hydrogen sulfide from a water source. Accordingto Themy, the electrooxidation cocktail removes hydrogen sulfide notonly by oxidizing hydrogen sulfide to elemental sulfur orsulfur-containing anions (e.g., SO₃ ⁻, SO₄ ²⁻), but it also destroyssulfide reducing bacteria (SRB), which may be responsible for productionof the hydrogen sulfide in some wastewater sources in the first place.Furthermore, some sulfur-containing organic compounds may be oxidized bythe electrooxidation cocktail to reduce their odor (e.g., thioethersoxidized to sulfoxides or sulfones), and further oxidation of thehydrocarbon portion of these molecules may take place as set forth Themyto remove them from the purified wastewater.

U.S. Patent Publication No. 2013/0312974, by McClung IV et al.(“McClung”) describes treating a well with a material to inhibithydrogen sulfide producing bacteria. McClung describes adding aninhibitor to a treatment fluid. The treatment fluid is added to a sourcecontaining bacteria that produces hydrogen sulfide to inhibit the growthof the bacteria. McClung is incorporated by reference in its entirety.

By way of providing additional background, context, and to furthersatisfy the written description requirements of 35 U.S.C. §112, thefollowing references are incorporated by reference in their entiretiesfor the express purpose of explaining the nature of the oil and gasindustry and methods to further describe the various systems,sub-systems, tools and components commonly associated therewith: U.S.Pat. No. 4,218,309, issued to Compton, U.S. Pat. Nos. 4,447,330 and4,536,293 issued to Babineaux, III, Japanese Patent Publication No.2008055291, invented by Mashahiko et al., Chinese Patent No. 101532380issued to Zhengguo.

The process to remove the sulfur content from sour water also requiresspecialized equipment, as sour water has corrosive properties. Using airto remove hydrogen sulfide, or “aeration,” as a unit operation dependson two basic principles: equilibrium conditions and mass transferconsiderations. The water to be treated is in equilibrium chemicallywith its component species and physically in equilibrium with theatmosphere above the water surface. These equilibrium conditions definethe limits of the gas transfer process. Aeration is an effective removalmechanism because hydrogen sulfide exists as a dissolved gas in somewater. Incidentally, the function of aeration is not specifically tooxygenate the water; rather it is to strip the dissolved gas (hydrogensulfide) out of the water by changing the equilibrium conditions of thewater and thus drive the dissolved gas out.

The removal of hydrogen sulfide by air stripping is defined byapplication of Henry's Law. Henry's Law, however, is generallyassociated with dilute solutions. Henry's Law relates the concentrationof a gas in the water to the partial pressure of the gas above theliquid. It is recalled that partial pressure is pressure that aparticular gas exerts as it moves toward equilibrium. Equilibrium occursas gasses flow from regions of higher partial pressure to regions oflower pressure. The larger this difference, the faster the flow.Hydrogen sulfide exists in equilibrium in three different forms as shownin the reactions below with their respective pK (disassociation) values.

H₂S═HS⁻+H⁺ pKa=7.1

HS⁻═S₂+H⁺ pKa=14

Certain facilities prohibit air stripping because of the potentialcombustible off gases and the costly residual air incineration, wherethe current processes in use teach away from using air to strip sourwater. Importantly, traditional processes of using air to strip sourwater are used primarily on sour water with very low contaminantconcentrations.

While it is known that air can potentially be used to strip water, themajority of current processes use specialized equipment, complicatedprocesses, or use natural gas or other materials to remove high levelsof hydrogen sulfide. For example, Japanese Patent No. 2008307475A,issued to Kyoji et al. (“Kyoji”), describes an apparatus and method toremove hydrogen sulfide from groundwater. Kyoji is incorporated byreference in its entirety. According to Kyoji, the preferred embodimentof the apparatus uses a pump to pump ground water into a storage tank. Apipe applies air to the water in the storage tank, releasing hydrogensulfide in a gas phase. The gas phase is then sent to a separatedesulfurizing compartment that contains a desulfurizing agent such asiron oxide or activated carbon. Air is then vented from thedesulfurizing compartment. The water is then sent to a separate tankwhere the water is processed to remove any suspended matter orprecipitate in the remaining water. The water is then discharged aftertreatment in the separate water treatment tank. Kyoji requires aseparate compartment from which air is vented to contain a desulfurizingagent, such as a chemical catalyst. Although Kyoji mentions that certainembodiments of the apparatus do not contain a separate desulfurizingcompartment, it is unclear if Kyoji's alternate embodiment would ventair directly from the compartment containing the sour water. Suchalternate embodiment does not account for human safety or environmentalsafety. Thus, Kyoji does not disclose a separate compartment, devoid ofany catalysts or additional desulfurizing agents, where theconcentration of hydrogen sulfide is measured before it is vented toensure the concentration of hydrogen sulfide is within the acceptablelimits.

European Patent Application Publication No. 2495219 (“EP '219”)describes a method for removing contaminants from feedwater. EP '219 isincorporated by reference in its entirety. EP '219 describes a methodthat includes forming a dispersion of bubbles of a treatment gas in acontinuous phase comprising feedwater, wherein the bubbles have a meandiameter of less than about 5 micrometers, and the gas is selected fromair, oxygen, and chlorine. The gas bubbles have a mean diameter of lessthan 1 micrometer, or no more than 400 nanometers (“nm”). In the methoddescribed in EP '219, the feedwater and treatment gas mixture and thecontinuous phase is subjected to a shear rate of greater than about20,000 s−1. The treatment gas and the continuous phase are contacted ina high shear device, wherein the high shear devices comprises at leastone rotor, and wherein the at least one rotor is rotated at a tip speedof at least 22.9 meters/second (4,500 feet/minute) during formation ofthe dispersion. The high shear device produces a local pressure of atleast about 1034.2 MPa (150,000 pounds per square inch, “psi”) at thetip of one rotor during the formation of the dispersion. The energyexpenditure of the high shear devices during the formation of thedispersion may be greater than 1000 W/m3. The dispersion is introducedinto a vessel and particle containing water is extracted from thevessel. The particle containing water is then introduced into aseparator. This method uses a specific mechanical device with veryspecific mechanical and process parameters to remove hydrogen sulfideand other contaminants from water. While its advantages (may becontained in a small footprint, may result in water suitable for directdisposal into surface lakes, streams or municipal water facilities,seems a fast process) appear useful in other work environments, they arenot needed for produced water transportation or disposal in remote orfield oil and gas production scenarios. Also, the advantages come at agreater cost not suitable for field use because the method uses aspecific mechanical device with very specific mechanical, power use andprocess parameters and it vents hydrogen sulfide and where chlorine gasis used a further possibly toxic, non-breathable mixture without regardto safely breathable concentrations.

In order to provide additional background information and further complywith disclosure requirements, the following documents are incorporatedby reference herein: U.S. Pat. No. 9,005,432 entitled “Removal of SulfurCompounds from Petroleum Stream” filed Jun. 29, 2010; U.S. Pat. Appl.Publ. No. 2015/0093314 entitled “Absorbent Composition for the SelectiveAbsorbtion of Hydrogen Sulfide and Process of Use Thereof” publishedApr. 2, 2015; Sour Water Strippers Exposed, by Ralph H. Weiland andNathan A. Hatcher, presented at Laurence Reid Gas ConditioningConference, Norman Okla., Feb. 28, 2012; and Partitioning of HydrogenSulphide in Wellstream Fluids, by CAPCIS, CAPCIS Limited, UK.

Other known aeration processes to remove hydrogen sulfide from water areunsuited for removing high levels of hydrogen sulfide as thoseencountered at exploratory sites. For example, certain processes havematerials containing hydrogen sulfide exposed to the open environment.This is problematic when materials have high levels of hydrogen sulfide,as the hydrogen sulfide escaping into the open environment is toxic andhazardous. Certain embodiments of the present invention comprise anenclosed environment for the materials containing hydrogen sulfide toprevent high concentrations of hydrogen sulfide to be released into theopen environment.

Other processes use catalysts to strip sour water. U.S. Pat. No.4,784,775 issued to Hardison (“Hardison”) discusses a system to removehydrogen sulfide from sour water using an aqueous chelated polyvalentmetal solution as a catalyst. The present invention removes hydrogensulfide from sour water without the need of a chemical catalyst.

Known sour water treatment processes are complex and have otherdisadvantages, such as requiring meticulous process parameters. Thepresent invention is novel and improves on the prior art because theonly parameter that must be closely monitored is the concentrations ofhydrogen sulfide in the air space that is eventually vented into openair. The present invention can be implemented with very minimalparameters. Deviations in the described process may affect the overalltime of the process or efficiency. However, as those skilled in the artcan recognize, deviations have little impact on the efficacy of theinvention. For example, in certain embodiments, perforations in thediffusion bar located in a tank containing sour water can be 0.25 inchesin diameter. In other embodiments, the perforations can be as small as0.05 inches in diameter. In yet other embodiments, the perforations canbe 1.00 inches in diameter. The present invention provides a simpler wayto remove hydrogen sulfide such that no automation is required. Althoughno automation is required for the present invention, certain embodimentsinclude automation. Any parameters described in certain embodiments arenot intended to limit the scope of the invention in any way and are onlyprovided as an example to illustrate the novelty and improvements of thepresent invention over the prior art.

Present methods of sweetening oil and stripping sour water is costrestrictive, and only becomes economical when performed in large scale.Building such facilities is impractical at exploratory sites. Thepresent invention, can be performed at any scale, using no more thanitems and equipment that would already be at the exploratory site andother items readily obtained from a local hardware store such as Lowe'sor Home Depot.

Treatment facilities can be inaccessible to those who are performingexploratory drilling. Furthermore, the equipment and materials requiredto perform traditional processes are not cost effective at exploratorysites. Those working at remote exploratory sites do not have access tothe resources needed to sweeten sour oil or sour water. For example,many of the typical processes use sweet natural gas to sweeten oil or tosweeten water. Often, a source of sweet natural gas is not readilyavailable, and it is not economical to sweeten sour natural gas in orderto use to treat sour oil or sour water.

Due to the remote nature of exploratory facilities, the toxic and deadlymaterials must be transported significant distances to a treatmentfacility. Anyone involved in the transportation is subject to thepotential hazards of hydrogen sulfide, as well as the potentialenvironmental disaster that could occur if something happens along theway from the remote well site to the treatment facility.

Certain embodiments of the invention provide a system and method tosweeten sour oil and water without a need to use hydrocarbons or othercatalysts. This is especially useful in the exploratory gas industrywhen access to traditional methods used to sweeten oil and water are notreadily available and could be many miles away. Certain embodimentsinclude a system and a method that comprise collecting the sour oil in acontainer, maintaining the sour oil in an air-free environment, addingwater, and agitating the mixture. Other embodiments of the presentinvention include using sour water to remove hydrogen sulfide from souroil.

SUMMARY OF THE INVENTION

The present invention relates to a system and method of removinghydrogen sulfide from oil and water. The present invention also reducesthe sulfur-by-weight content. Current ways to remove hydrogen sulfidefrom oil and water typically use specialized equipment and expensivechemicals. Hydrogen sulfide is a toxic chemical, and transportation ofmaterials that contain high levels of hydrogen sulfide presents dangersto all those involved. This is especially problematic for exploratorywells, which are often located hundreds of miles away from the closesttreatment facility. The present invention comprises treating oil orwater to remove hydrogen sulfide. The present invention can be used withsour water and sour oil with high levels of hydrogen sulfide as well aslower levels. The hydrogen sulfide is removed without specializedequipment or expensive chemicals. The sweetened water or sweetened oilcan be transported without placing those involved in handling andtransportation at risk of potentially fatal mishaps and minimizes andenvironmental hazards.

In certain embodiments, the invention comprises an air source, a tank, aplurality of lines that distribute air from the air source to the tankand a vent stack, connections that distribute the air from the airsource into the tank, a hydrogen sulfide monitor, and a vent stackconnected to the water tank and air source. The air from the air sourceruns to a tank filled with sour water through an airflow line. Theairflow line is connected to a pipe with at least one hole. The pipe islocated in the water tank. A second line runs to the vent stack througha second airflow line. In certain embodiments, air flows to the ventstack at a rate of 120 standard cubic feet per minute (“scf/m”). Theairflow is adjusted incrementally every hour for twelve hours. The airdistribution ratio is adjusted hourly until the ratio of airflow to thewater tank line increases to about 120 scf/m and the airflow to the ventstack decreases to about 20 scf/m. The amount of hydrogen sulfide ismeasured near the top of the vent stack. The air with the acceptablelevels of hydrogen sulfide is then vented. The plurality of linesrunning from the air source are secured by typical ways known to thoseskilled in the art to connect air lines to air source. Embodiments ofthe present invention ensure that any materials containing hydrogensulfide are enclosed within the invention and not exposed to the outsideenvironment. As those skilled in the art will recognize, the air sourcecan be any air source able to generate air, such as a compressor or ablower.

U.S. Pat. No. 3,547,190 issued to Wilkerson (“Wilkerson”), describes anapparatus and method for treating waste water associated withhydrocarbon production. Wilkerson is incorporated by reference in itsentirety. According Wilkerson, waste water from a well is pumped underpressure to a plurality of spray nozzles which are disposed in such amanner as to spray the water into the atmosphere in a substantiallyvertical direction in open air. The sprayed water is thus aerated toremove the residual hydrogen sulfide therefrom and reduce itstemperature. The water is then collected in a basin wherein any excessoil still associated with the water may be skimmed from the surface ofthe water. The method described in Wilkerson would lose efficiency asthe temperature of the process water decreases from boiling point. Insome specific field applications where water coming from the well itselfis very hot, this method may be useful. For all other fieldapplications, there are problems with its implementation. For example,it operates in a fairly narrow envelope of parameters, both mechanicaland process. Nozzle-size and upstream pump pressures will be fairlycritical. It may result in mist (as opposed to vapor) being blown ontoadjoining property, legally a spill. Wilkerson requires hot water forefficiency and may not be suitable for cold-weather applications,regardless of the temperature of the initial process water.

Of note, Wilkerson vents hydrogen sulfide without regard to safelybreathable concentrations. Any hydrogen sulfide not vented in theinitial pass vents from an open body of water at a rate that is bothdifficult to measure and difficult to control. This particular method isvery problematic in this regard, and as those skilled in the art canrecognize, the present invention alleviates the safety hazardsassociated with releasing hydrogen sulfide into the environment.Although it is known in the art that exposing water or oil containinghydrogen sulfide to air will remove hydrogen sulfide, embodiments of thepresent invention allow the aeration to remove hydrogen sulfide in anenclosed environment to eliminate any safety risks and environmentalhazards associated releasing hydrogen sulfide in an open environment.

In other embodiments, the present invention comprises a container filledwith water, a separate container filled with oil, a means to distributewater from the container filled with water to the container filled withoil. The water can be sweet water or sour water. The water travelsthrough the sour oil as it has a lower specific gravity. This travelthrough the oil creates an agitation, and the hydrogen sulfide isremoved from the oil as the water passes through the oil. The agitationoccurs at the oil/water interface. Oil will release hydrogen sulfideinto the water wherever water containing a lower hydrogen sulfideconcentration contacts oil containing a higher hydrogen sulfideconcentration.

U.S. Pat. No. 3,977,972 issued to Bloch et al. (“Bloch”) describes asystem and a method to remove hydrogen sulfide from seal oil throughbubbling a gas such as nitrogen. Bloch is incorporated by reference inits entirety. Bloch's preferred embodiment contains a compressor havinga shaft which rotates in a pair of liquid-film seal cartridges whichserve as seal retainer housings for the rotary shaft of the compressor.Each of the liquid-fill seal cartridges includes a pair of floating,non-rotation sleeve portions surrounding the shaft and interconnected byan intermediate space portion through which the shaft freely extends.Contaminated oil is then transferred to a cylindrical drum, where thediameter of the drum may be on the order of two feet while its heightmay be approximately twice the diameter. The lower interior portion ofthe drum is provided with a baffle in the form of a simple flat sheet ofmetal extending upwardly approximately 2 feet from the bottom of thedrum to divide the lower interior portion of the drum into a pair ofchambers which has a cross section of a semicircle. Contaminated sealoil flows into one of the chambers, where a sparger means bubbles up airor nitrogen through the oil. The oil flows to the second chamber, wherea sparger means bubbles up air or nitrogen through the oil. Bloch, whilepossibly suitable for refined seal and lubrication oils that may becomecontaminated by higher sulfur fuels, is neither suitable nor safe to usewith crude oils or any other oil that releases combustible case into theair. Although the use of pure nitrogen or another inert gas mightaddress combustion problem, it is impractical and uneconomical to obtaina pure nitrogen source at exploratory sites, and would also create a lowoxygen environment (breathable oxygen) in the area near the vent.Neither is it suitable for higher concentrations (above 10 ppm) ofhydrogen sulfide due to its direct, un-diluted vent. As those skilled inthe art can appreciate, the use of water to remove hydrogen sulfidecontent in oil reduces the risks associated with adding an outside airsource to a combustible material such as oil.

In certain embodiments, nitrogen can be used to keep the oil-waterinterface fresh, where the water agitation sweetens the oil. Nitrogen isintroduced into the bottom of the oil stripping tank periodically at alow volume, for example, at a rate of 10 standard cubic feet every 15minutes as an additional safety measure to prevent flammable gasbuildup.

In certain embodiments, the present invention comprises a tank with amixture of oil and sour water, a separate tank with sour water, airdistributers pumping air through the tank with sour water to removehydrogen sulfide, pumping the sweetened water into the tank containingthe oil and water mixture, and allowing the water from the oil and watertank to flow into the sour water tank through a gravity-feed. As thoseskilled in the art can appreciate, the present invention is animprovement to the prior art that requires the use of catalysts,scavengers or other expensive and specialized equipment.

Certain embodiments of the present invention can be implemented usingcontainers typically used in the oilfield, such as commonly used 500barrel “frac” tanks and 400 barrel cylindrical upright tanks. In oneembodiment, a 185 scf/m air compressor derated for 5000 feet elevationto 140 scf/m can be used as the air source. A disperser bar with atleast one hole is placed in the water tank. The disperser bar can be 1″or 1.5″ pipe. The vent line from the water tank to the vent stack is 3″in diameter.

The equipment described herein is provided as an example only and shouldnot be construed to limit the present invention, as the presentinvention can be used in almost any scale, For example, the presentinvention can be used with samples smaller than 500 ml oil or water aswell as tanks having a volume in excess of 1000 barrels.

For example, certain embodiments comprise equipment that can be placedin mobile transportation, such as a trailer or the back of a pickuptruck. Certain tanks, which are commercially available, are designed tofit in the back of a pickup truck. This embodiment allows easy transportand allows sour oil and sour water located in remote locations wherelarger equipment is uneconomical, impractical, or impossible because ofthe remote area.

In certain embodiments, the equipment can be placed in a tow trailer,where the invention comprises a configuration comprising an automationcabinet, an air source, a power source, such as a generator, a waterpump, and hose or piping connectors. As those skilled in the art canappreciate, variations of this embodiment can also be practiced withother types of tanks that are mobile and can be transported from site tosite, and are within the spirit of the invention. The descriptionsherein are not intended to limit the present invention.

In certain embodiments, the invention comprises an air source, aplurality of storage devices, connections that distribute the air fromthe air source into a storage device comprising water, and a vent stackconnected to the storage device comprising water and air source. The airfrom the air source runs to the storage device comprising sour waterthrough an airflow line. The airflow line is connected to a pipe with atleast one hole. The pipe is located in the storage device comprisingsour water. A second line runs to the vent stack through a secondairflow line. In certain embodiments, air flows to the vent stack at arate of around 120 scf/m. The airflow is adjusted incrementally everyhour for twelve hours. The air distribution ratio is adjusted hourlyuntil the ratio of airflow to the water tank line increases to around120 scf/m and the airflow to the vent stack is decreased to around 20scf/m. The amount of hydrogen sulfide is measured near the top of thevent stack. The air with the acceptable concentrations of hydrogensulfide is then vented. The sweetened water is then pumped from thewater tank to a second storage device comprising a mixture of sour oiland water through an attachment attaching the water tank to the top ofthe second storage device comprising sour oil and water. The storagedevice comprising a mixture of sour oil and sour water is equalized.Water is pumped from the storage device comprising sour water into thestorage device comprising the mixture of sour oil and water. Forexample, in embodiments comprising 400 or 500 barrel tanks, a suitablerate would be pumping water from the storage device comprising waterinto the storage device comprising the mixture of sour oil and water ata rate of 3 barrels per minute. Other rates are also possible, such as arate of 20 to 50 gallons per minute. As the water passes through the oildue to its higher specific gravity, hydrogen sulfide is removed from theoil. The water that is now at the bottom of the storage devicecomprising oil and water has higher concentrations of hydrogen sulfide.The water from the bottom of the storage device comprising oil and waterflows back to the storage device comprising water due to hydrostaticpressure, i.e., a “gravity feed,” through an attachment between thebottom of the storage device comprising oil and water tank and storagedevice comprising water. The water is then stripped to remove hydrogensulfide so that the concentrations of hydrogen sulfide reach a levelthat is acceptable to vent. Embodiments of the present invention ensurethat any materials containing hydrogen sulfide are enclosed within theinvention and not exposed to the outside environment.

Certain embodiments of the invention include a cavitation vent to keepair out of the oil stripping tank.

In certain embodiments of the invention, the water used in the strippingprocess comprises a pH of approximately 7.2 or below. In certainembodiments, the removal of all hydrogen sulfide may be desired. Inembodiments where all hydrogen sulfide is desired to be removed, thehydrogen sulfide could be completely removed once environmentaltemperatures are above 45 degrees Fahrenheit.

Another embodiment of the invention includes a way to automateregulation of air distribution. In certain embodiments, a loopcontroller is attached to a hydrogen sulfide sensor monitoring theconcentration of hydrogen sulfide from the vent stack. In thisembodiment, the loop controller is attached to the vent stack, the airline to the water stripping tank, and the air line to the vent stack.The loop controller is used to keep the air vented below 10 ppm. Theloop controller is connected to a current to pressure converter (“I to Pconverter”). In certain embodiments, the I to P converter converts thecontroller 4 to 20 ma output to 0 to 15 psi pneumatic. As those skilledin the art can appreciate, different types of I to P converters may beused with the present invention, and the I to P converter describedherein is not intended to limit the present invention.

Certain embodiments include at least one I to P converter. A specificair line could be regulated by a dedicated I to P converter. In otherembodiments, the I to P converter could regulate a plurality of airlines. In preferred embodiments, the use of one I to P converter may beadvantageous because it assures a “safe state” upon loss of controlsignal (either electric or pneumatic) where all the air would divertinto the vent stack, and the valves would return to their defaultposition.

Based on the information received from the loop controller, the I to Pconverter or converters will send more air to the air line connected tothe vent stack and less air to the air line connected to the tankcomprising water, i.e., the water stripping tank, as the hydrogensulfide stream exceeds 10 ppm when the hydrogen sulfide monitor reads aconcentration exceeding 10 ppm. If a concentration detected by thehydrogen sulfide sensor falls below 10 ppm, the loop controller sendsmore air to the air line connected to the water stripping tank. Incertain embodiments, the loop controller could be calibrated where itwould reset at a one minute interval, and also calibrated so that thereis a variance range of 2 to 3 ppm where no change in control to the airlines would be transmitted.

In certain embodiments, the automation can be controlled with anautomation control. The automation control allows for measurement of thenumber of barrels of oil sweetened by the present invention.

In certain embodiments, the automation control comprises a programmablelogic controller (“PLC”), a plurality of compartments, an air source,connections that distribute the air from the air source to the desiredcompartments, a pumping means, sensors, sensor cables, and a vent stackconnected to a compartment comprising water. A first compartment isfilled with water which can comprise hydrogen sulfide. A secondcompartment is filled with a mixture comprising sour oil and sour waterin an equalized amount. The sensors are attached by sensor cables to thecompartments comprising water, sour oil and sour water, and a ventstack. Water from the first compartment is distributed to the secondcompartment through a connection located at the top of the secondcompartment. As the water passes through the oil due to its higherspecific gravity, hydrogen sulfide is removed from the oil. The sensorin the second compartment detects the amount of hydrogen sulfide in thesecond compartment. The water that is now at the bottom of the secondcompartment has higher concentrations of hydrogen sulfide. The waterfrom the bottom of the second compartment flows back to the firstcompartment comprising water due to hydrostatic pressure through anattachment between the bottom of the second compartment and the firstcompartment. The sensor in the first compartment measures the amount ofhydrogen sulfide in the first compartment. The sensor in the vent stackalso measures the amount of hydrogen sulfide in the vent stack. Air isdistributed to the first compartment from the air source through anairflow line. The sensor in the first compartment measures the amount ofhydrogen sulfide present in the first compartment. The sensor in thevent stack measures the amount of hydrogen sulfide present in the ventstack. Once the sensor detects the amount of hydrogen sulfide is withinthe desired limit programmed into the PLC, air is automatically vented.Sweetened water is then pumped from the first compartment to the secondcompartment. As those skilled in the art can appreciate, the sensorsmonitor the amount of oil sweetened by the process.

In other embodiments, the data regarding the number of barrels of oilsweetened is transferred remotely to a database where the number ofbarrels of oil sweetened can be stored and analyzed. This data transfercan occur via wireless means including cellular internet protocol,Bluetooth, or other wireless data transfers.

Other embodiments use a high pressure, low volume water pump tocirculate stripped water through a sample to remove hydrogen sulfide.These embodiments comprises an air compressor or air pump, a containerused as a water stripping reservoir, a high pressure, low volume pump, arelief regulator, a container filled with an oil sample pressurized tothe sampled psi, a container filled with a water sample, and a liquidpressure regulator. The air compressor or air pump pumps air into thereservoir containing water to be stripped. For example, a CoralifeSL-381.3 scfm pump may be used. Air is then pumped into a waterstripping reservoir. The water stripping reservoir is at atmosphericpressure. An example of the water stripping reservoir may comprise aplastic or metal material with a five to ten liter capacity. The waterstripping reservoir is filled to ¾ or ⅝ of its volume capacity withdistilled water. Water from the water stripping reservoir then travelsto a high pressure low volume pump. The pump may comprise a pneumaticpump or an electric pump. For example, the pump may comprise a Texsteam5000 series. A relief regulator is connected to the high pressure lowvolume pump, and vents as necessary. As an example, the relief regulatormay be set at the sample container MAOP, such as 2000 psi. The waterfrom the high pressure low volume pump then travels to a container withthe oil sample. For example, certain embodiments may use a 1000 cubiccentimeter (“cc”) container, pressurized at 75 psi. The water passesthrough the oil sample container to a separate container, containing awater sample. In certain embodiments, the container for the water samplemay comprise a 1000 cc container. The water then passes from the watercontainer back to the water stripping reservoir. A liquid pressureregulator may be attached to the line traveling from the container withthe water sample to the water stripping reservoir. The liquid pressureregulator may be set at the oil sample pressure, e.g. 75 psi.

In yet another embodiment, the present invention comprises a containerfilled with water, a separate container filled with oil, a distributingmeans that distributes water from the container filled with water to thecontainer filled with oil.

In certain embodiments, the invention includes of filling a tank withsour water, aerating the sour water to strip the sour water, pumping thesweetened water into a separate tank comprising an equalized mixture ofsour oil and sour water, removing hydrogen sulfide from the sour oil,pumping the resulting sour water into the tank filled with sour water.

In certain embodiments, the invention includes components that can beused in remote areas, such as exploratory wells. As those skilled in theart can recognize, the invention eliminates the need for expensive andspecialized equipment that is currently used to remove hydrogen sulfidefrom sour water and sour gas. Furthermore, the invention can be used tostrip sour water and treat sour oil containing hydrogen sulfide in anyamount, even exceeding 300,000 up to saturation—an amount higher thanequipment that taught in the prior art. For example, U.S. Pat. No.5,286,389 issued to Hardison (the “Hardison '389 Patent”), incorporatedin its entirety by reference, describes a system and apparatus to striphydrogen sulfide from water. The Hardison '389 Patent method andapparatus specifically states the apparatus and method is particularlyeffective to treat sour water containing around 5 ppm to 500 ppmhydrogen sulfide. Thus, the Hardison '389 Patent teaches away from usingsuch prior art with water containing high levels of hydrogen sulfide.The levels of hydrogen sulfide do not influence the present invention,and the present invention can be used with materials containing veryhigh levels of hydrogen sulfide.

U.S. Pat. No. 6,444,117, issued to Kahn et al. (“Kahn”), describes aprocess for desulfurizing sulfur-containing crude oil streams. Kahn isincorporated by reference in its entirety. Kahn requires heating thesulfur containing crude oil to an elevated temperature to at least 300degrees Fahrenheit (149 degrees Celsius) to about 600 degrees F. (316degrees C.) for an extended period of time, stirring and bubbling aninert gas, such as nitrogen into the crude oil, and adding a scavengeror catalyst into the crude oil stream to generate an exhaust gas such ashydrogen sulfide. Kahn requires a careful monitoring of and controlliquid temperature to remain safe. Its maximum efficiency envelopeimmediately borders the flash-point of the oil sweetened (unsafe). Theseparameters must be monitored and controlled constantly and will varywidely with different types and grades of crude oil. Kahn acknowledgesthat additional steps may be required to reduce the amount of hydrogensulfide generated by heating the crude to the levels described. Kahnvents both hydrogen sulfide and low-oxygen mixture without regard tosafely breathable considerations. As those skilled in the art canappreciate, the present invention is a much simpler process that is muchsafer than what is known in the prior art.

United States Patent Application No. 2013/0324397, by Wilson et al.(“Wilson”) describes using a carbon adsorbent for hydrogen sulfideremoval. The hydrogen sulfide adsorbent is added to the materialcontaining hydrogen sulfide. Wilson is incorporated by reference in itsentirety.

The present invention involves a system and a method that removeshydrogen sulfide from water and oil in a very cost effective manner.Furthermore, certain embodiments allow the hydrogen sulfide to beremoved on-site at remote locations, such as exploratory wells. Certainembodiments allow removal of hydrogen sulfide from water and oil,diluting the concentration to amounts that can be safely vented into theenvironment, in accordance with current environmental and safetyregulations and without endangering anyone in the surrounding area, anyanimal in the surrounding area or the environment.

The present invention also reduces sulfur by weight. Typical worldwidedefinition for sour oil is generally about 0.5% sulfur by weight. Thepresent invention can be used to sweeten oil such that the oil is lowerthan the 0.5% acceptable rate.

Other embodiments are directed to improving the price spread, which isthe value of sweet oil versus sour oil, measured in dollars. The pricespread can vary between $5 USD and $16 USD per barrel. It is difficult,and not usually feasible, to blend out high volumes of hydrogen sulfidein oil. It is not difficult, but may be costly, to blend out high sulfurweights. One would have to blend a prohibitive amount of 0% ppm hydrogensulfide with 10,000 ppm oil in order for the resulting total volume tocurrently accepted limits of 0.5% or 5 ppm. By first treating oils asdescribed herein, then blending oils in a 1:1 ratio or equal volumes of0.1% sulfur by weight would result in a sweet-price oil. Blending istypically expensive, but by first treating oils as described herein,provides a low cost method of minimizing the post-process blendingratio, or eliminates the need to blend oils to increase the pricespread.

Certain embodiments of the present invention include a plurality oftanks containing different levels of sour oil. The oil in one of thetanks can be treated to remove hydrogen sulfide and then blended withoil from another tank to improve the price spread.

Other embodiments comprise an additional chamber where the removal ofhydrogen sulfide from the air can be further stripped thus increasingthe rate of hydrogen sulfide removal before venting once the hydrogensulfide levels are within the desired limits.

In yet another embodiment, the system and method comprise safe transportof sour water and sour oil from a remote area such as an exploratorywell. High concentrations of hydrogen sulfide are extremely toxic anddeadly. Transportation of such materials is extremely dangerous and putseveryone involved at risk, from the personnel handling the materials atthe site, those involved in loading the transportation vehicle, thedriver of the transportation vehicle, to the personnel at the treatmentplant unloading the toxic materials. The danger of a deadly mishapincreases as more people have to handle the toxic materials, and thegreater the distance traveled further puts the handlers at risk. Incertain embodiments, the present invention involves a system and methodto neutralize the risk involved in transporting toxic materials, such assour water and sour oil with high concentrations of hydrogen sulfide. Asthose skilled in the art can appreciate, the present invention rendersthe transport of materials high in hydrogen sulfide unnecessary, thusimproving the safety to those involved in transporting the materials,and reducing liability that may result should an accident occur duringtransportation.

Use of the current invention at exploratory wells is especiallybeneficial. For example, when a crew is at an exploratory well, theytest to see the quality of wells for hydrogen sulfide. At some wells,the levels are extremely high, and cause a danger to any person in thearea. In order for samples to be provided for further analysis, the crewsubjects themselves to the danger not only in the levels of hydrogensulfide in the sour oil and sour water, but also dangers in transportingsamples. In order to transport any of the sour oil or the sour water, acrew would have to wear full protective gear to load the truck tankers.Then the crew would have to travel over arduous roads with sour oil orsour water containing hydrogen sulfide in such high concentrations thatit could cause sudden death. Any accident along the way would releasesuch hazardous chemicals, and could kill the drivers, as well as dueextensive harm to the environment. Even when the drivers reach thesample or treatment facility, the crews at those facilities are placedat risk. Any error in the process could prove fatal.

The present invention neutralizes this risk. In certain embodiments,there is no need for expensive chemicals, which themselves arehazardous, and the invention eliminates the need to haul a potentiallydeadly toxin or toxins long distances, whether hydrogen sulfide,chemical scavengers, chemical catalysts, or other chemicals. Otherembodiments allow oil and water with high concentrations of hydrogensulfide to be sweetened on site before loading the trucks to transport,transporting the sweetened water or oil, and unloading the sweetenedwater or oil at a facility that will run further analysis or even tosell the sweetened oil.

For example, in certain embodiments, sour oil or sour water would bedetected at an exploratory site, far away from a facility that couldtreat the sour oil or sour water to remove levels of hydrogen sulfide.In this embodiment, the sour water and sour oil is treated in accordancewith the present invention at the exploratory site for easytransportation. This includes aerating sour water contained in one tank,monitoring the amount of hydrogen sulfide concentration in the watertank, venting air from the vapor space of the water tank when thehydrogen sulfide is at acceptable levels, pumping the sweetened waterfrom the water tank into a separate tank containing an equalized souroil and water mixture, continuing to pump water into the tank containingthe oil and water mixture until the amount of hydrogen sulfide in theoil is at acceptable levels, returning water from the tank containingoil and water to the water stripping tank, continuing to aerate thewater until the levels of hydrogen sulfide are acceptable. Then, the oilis removed from the tank containing oil and water, loaded into anothercontainer for shipment, such as a tanker. The oil, having little to nohydrogen sulfide content is then transported from the exploratory siteto a destination where the oil could be subjected to other tests, oreven sold. The water could be re-used in the process, or could betransported from the exploratory site to a destination for furthertesting or disposal. As those skilled in the art can appreciate, therisks involved in transportation of materials containing hydrogensulfide is reduced or eliminated, as the transported materials containlittle or no hydrogen sulfide. In other embodiments, the inventionaddresses an unknown danger except for those involved regardingtransportation of sour oil or sour water. In certain embodiments thetransportation method comprises shipping oil or water via a commoncarriers or private carriers, including via FedEx or UPS. Since there islittle to no hydrogen sulfide in the materials, no additionalprecautions need to be taken to ship the materials.

Other embodiments of the present invention include a container thatindicates the levels of hydrogen sulfide in the materials within thecontainer. In these embodiments, the container provides a certainindication that the levels of hydrogen sulfide are below toxic amountsand can be transported safely. The container and display can becalibrated according to the relevant regulations to indicate when thehydrogen sulfide level content is below the required levels. This isparticularly useful when further analysis on samples from a remote wellneed further analysis at an off-site location. One of the importantaspects of the present invention is its flexibility to be used inmultiple scales. Thus, hydrogen sulfide can be removed from smallervolumes of sour water or sour oil by the present invention, such aswithin a specialized container that indicates that the materials withinthe container are safe to ship. In another example, the calibration canbe set to indicate that no hydrogen sulfide is present, and the oilcould be sold to a refinery.

Yet another embodiment of the present invention comprises an indicatorthat displays a corresponding message or display regarding the amount ofhydrogen sulfide content in the materials to be shipped. The indicatorcan be integrated with a container, or as a stand-alone indicator. Theindicator displays information on proper handling of the materials thatare to be transported. With the information, decisions on safe handlingand safe shipping of the materials can be made. For example, a decisionto ship the materials via truck, via parcel, via common carrier, orwhether the materials are even safe to transport at all can be made fromthe information. For instance, if the indicator displays that thehydrogen sulfide level is close to zero, it would indicate safe shippingby any shipment method that would allow the transport of non-hazardousmaterials similar to those being shipped.

While various embodiments the present invention have been described indetail, it is apparent that modifications and alterations of thoseembodiments will occur to those skilled in the art. However, it is to beexpressly understood that such modifications and alterations are withinthe scope and spirit of the present invention, as set forth in thefollowing claims. Further, the invention(s) described herein are capableof other embodiments and of being practiced or of being carried out invarious ways. In addition, it is to be understood that the phraseologyand terminology used herein is for the purposes of description andshould not be regarded as limiting. The use of “including,”“comprising,” or “adding” and variations thereof herein are meant toencompass the items listed thereafter and equivalents thereof, as wellas, additional items.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of the specification, illustrate embodiments of the invention and,together with the general description of the invention given above andthe detailed description of the drawings given below, serve to explainthe principals of this invention.

It should be understood that in certain instances, details that are notnecessary for an understanding of the disclosure or that render otherdetails difficult to perceive may have been omitted. Further, thedrawings of the system and/or method do not detail all features of thesystem and/or method, and do not show the entire system and/or method.It should be understood, of course, that the disclosure is notnecessarily limited to the particular embodiments illustrated herein.

FIG. 1 depicts certain embodiments of the invention to remove hydrogensulfide from oil and water;

FIG. 2 depicts certain embodiments of the invention that are mobile;

FIG. 3 depicts certain embodiments of the invention to remove hydrogensulfide from water;

FIG. 4 depicts certain embodiments of the invention that allows removalof hydrogen sulfide in a smaller scale;

FIG. 5 depicts certain embodiments of the invention comprising a loopcontroller to regulate air flow;

FIG. 6 depicts certain embodiments of the invention that use a commoncontainment vessel;

FIG. 7 depicts certain embodiments of air injection;

FIG. 8 depicts certain embodiments of the invention as part of anoverall hydrocarbon recovery, processing and transportation system; and

FIG. 9 depicts certain embodiments of a sulfur reduction or sulfurremoval system.

It should be understood that the drawings are not necessarily to scale.In certain instances, details that are not necessary for anunderstanding of the invention or that render other details difficult toperceive may have been omitted. It should be understood, of course, thatthe invention is not necessarily limited to the particular embodimentsillustrated herein.

To assist in the understanding of the present invention the followinglist of components and associated numbering found in the drawings isprovided herein:

# Component 1 System 10 Sour water container 11 Air compressor 12 Capassembly element 13 Line 14 Air dispenser bar 15 Vapor space air 16 Ventstack 17 Air distribution line 18 Meter gauge 19 Line 20 Distributionpump 21 Line 22 Attaching line 23 Sour oil container 24 Second line 26Water pump 27 Automation cabinet 28 Air source 29 Storage rack 30 Singlevessel 31 Trailer 32 Partition 34 Aperture 41 Pump 42 Well head 43 Wellhead line 44 Site tank farm 45 Site tank farm line 46 Offsite tank farm47 Offsite tank farm line 50 Treator/separator 52 Separated gas line 53Converter 54 Treator/separator line 55 Pneumatic signal 60 Gasdistribution 62 Sweetened Oil line 70 Vehicle 72 Rail 74 Ship 76Pipeline h Depth height

DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS OF THE INVENTION

FIG. 1 provides a diagram depicting certain embodiments of the inventionrelated to a system 1 to remove hydrogen sulfide in water and oil.Element 10 is a container comprising sour water. Element 11 is an aircompressor used to distribute air to elements 10 and 16. Element 17 is aline from element 11 to distribute air to element 10, sealed by a capassembly, element 12. Element 13 is a line running from cap assemblyelement 12 to an air dispenser bar. Element 14 is an air dispenser bar.Element 14 is submerged in the sour water located in element 10. Inalternate embodiments, air dispenser bar 14 is disposed in any locationwithin the container 10, to include the center portion and the upperportion of container 10. The air in the vapor space is transferred byelement 15 to a vent stack, element 16. Element 24 is a second linerunning from element 11 to element 16, where air from the air compressordilutes air transferred from the vapor space to the vent stack. Element18 is a gauge that meters the amount of hydrogen sulfide in element 16.The air in the vent stack 16 may be distributed in any of several ways,comprising release to the atmosphere, flaring i.e. burning, andcapturing for storage, transport or sale. Also, the vent stack 16assembly could be modified or substituted to include the further sulfurprocessing, e.g. a sulfur reduction/removal system (see, e.g. FIG. 9 andassociated description.)

Element 23 is a container comprising sour oil and water. The oil andwater in element 23 are equalized. Element 19 is a line from element 10to element 20. Element 20 is a pump that distributes lean water fromelement 10 to element 23. Element 20 pumps the water through element 21,a line running from element 20 to the top of element 23. In alternateembodiments, line 21 emits water to other than the top of element 23,e.g. from the bottom or side of element 23 (see, e.g. FIG. 7 andassociated description.) In alternate embodiments, the oil and water inelement 23 are not equalized.

As the water is pumped into element 23, it passes through the sour oildue to a lower specific gravity. As the water travels through the souroil, it obtains hydrogen sulfide from the oil, thus removing hydrogensulfide from the oil. The water then returns to element 10 throughelement 22. Element 22 is a line attaching element 23 to element 10. Thewater runs from element 23 to element 10 via hydrostatic pressure. Inalternate embodiments, the water runs from element 23 to element 10 viaother than hydrostatic pressure, e.g. via one or more pumps. Hydrogensulfide is removed from the water that returns from element 23 asdescribed above. Those skilled in the art can appreciate that theparticular elements in the embodiment depicted in this figure areconnected using typical connections known to those skilled in the art,such as the appropriate seals, caps, clamps, tubes, o-rings, splittervalves, etc. An important aspect of the present invention is that nospecialized equipment is necessary, and the items used are those readilyavailable to those skilled in the art.

FIG. 2 provides certain embodiments of the invention that are mobile.Element 26 depicts a water pump. Element 27 depicts an automationcabinet. Element 28 depicts an air source. Element 29 depicts a rackwhere appropriate connections, such as piping or hose can be stored.Element 30 depicts a power source, such as a generator. Element 31depicts a trailer. In one embodiment, trailer 31 is acommercially-available trailer to include those conventionally found onhydrocarbon production sites.

FIG. 3 provides a diagram depicting the system 1 configured to removehydrogen sulfide from water without coupling to a system to removehydrogen sulfide from oil. Element 10 is a container comprising sourwater. Element 11 is an air compressor used to distribute air to element10. Element 17 is a line from element 11 to distribute air to element10, sealed by a cap assembly, element 12. Element 12 is secured toelements 11 and 17 using typical items known to those skilled in theart. Element 13 is a line running from cap assembly element 12 to an airdispenser bar, element 14. Elements 12, 13, and 14 are attached usingtypical means known to those skilled in the art. Element 14 is submergedin the sour water located in element 10. In alternate embodiments, airdispenser bar 14 is disposed in any location within the container 10, toinclude the center portion and the upper portion of container 10. Theair in the vapor space is transferred by element 15 to a vent stack,element 16. Element 24 is a second line running from element 11 runs toelement 16, where air from the air compressor dilutes air transferredfrom the vapor space to the vent stack. Element 18 is a gauge thatmeters the amount of hydrogen sulfide concentration in element 16. Inone alternate embodiment, container or tank or storage vessel 10 is acommercially-available tank, to include those of rail cars and trucktanks, and any of standard field tanks, to include both low profile(generally equal or less than 16 feet in height) and high profile tanks(generally those greater than 16 feet in height). The air in the ventstack 16 may be distributed in any of several ways, comprising releaseto the atmosphere, flaring i.e. burning, and capturing for storage,transport or sale. Also, the vent stack 16 assembly could be modified orsubstituted to include the further sulfur processing, e.g. a sulfurreduction/removal system (see, e.g. FIG. 9 and associated description.)

The system 1 of FIG. 3 enables re-cycling of production sour waterwhich, when sweetened, may be reused in well production or be depositedon-site for irrigation or other purposes. In one example use, thesweetened water of system 1 may be used as part of ahydraulic-fracturing (ie. “fracking”) operation to remove H₂S fromfracking blowback water, wherein the treated water may be re-used forfracking or other production uses, or disposed of by means whichprohibit H₂S.

In one embodiment of system 1 (not pictured), the system 1 is configuredto remove hydrogen sulfide from oil without coupling to a system toremove hydrogen sulfide from water. Such a configuration of system 1would require a supply of water substantially free of H₂S (to input asline 21 to a tank 23 of sour oil) and a means to dispose of sour water(as output as line 22) from the tank 23.

FIG. 4 depicts certain embodiments of the system 1 that allows removalof hydrogen sulfide in a smaller scale. Element 41 depicts a pump.Element 41 is connected to element 45 via element 49. Element 41 pumpswater from element 45 through element 42 into element 43. Element 43 isa container filled with sour oil and water. Water from Element 43 flowsthrough element 44 into element 45. Element 45 depicts a containerfilled with water. Element 46 depicts an air source. Element 46distributes air through element 47 into element 45. Element 48 depicts avent connected to element 45. In one embodiment, the system 1 of FIG. 4is portable and/or may be transported on a single commercially-availabletruck or railcar.

FIG. 5 provides a diagram depicting certain embodiments of the inventioncomprising an I to P converter that regulates air flow to a plurality ofair lines. Air compressor, element 11 is connected to element 17, a linerunning air to a tank containing sour water and element 24, a linerunning air to a vent stack. Element 55 is connected to element 53 byelement 54. Element 53 converts an electrical signal from element 55into a pneumatic signal. The signal from element 53 is relayed byelement 52 to elements 50 and 51. Based on the input signal from element53, element 50 may increase or decrease the amount of air flowingthrough element 17. Based on the input signal from element 53, element51 may increase or decrease the amount of air flowing through element24. Although this diagram depicts a preferred embodiment, othervariations to this embodiment, such as using a plurality of I to Pconverters may be used and is within the spirit of the presentinvention.

In certain embodiments, the water may enter the sour water container 23via line element 21 by other than the top of the container, e.g. fromthe side or bottom of the container. For example, the water entering thetank 23 from line 21 may enter the tank 23 at any vertical locationalong the tank 23 and at the bottom the tank 23. In some configurations,one or more pumps, such as the pump 20, are employed to deliver water totank 23.

In certain embodiments, the water provided to tank 23 is by any means soas to provide or maintain a circulation of water at an interface withthe sour oil in tank 23. Stated another way, any means of circulatingwater from the water sweetening tank through to the oil sweetening tankand then back into the water sweetening tank may be implemented. Inanother embodiment, the water provided to the tank 23 may interface withthe sour oil such that the water moves vertically or rolls so as to keepthe oil/water interface as fresh as possible. In another embodiment, thewater rotates on a horizontal plane. In another example, the tank 23employs mixers comprising agitators, baffles and similar devices knownto those skilled in the art to mix the water and the sour oil.

In one embodiment, in addition to water, oil is circulated through thetank 23. In one embodiment, the only fluid circulated through system 1is water.

In one embodiment, the size configuration, and quantity of tanks isvaried. FIG. 1 depicts an embodiment having one oil sweetening tank 23and one water sweetening tank 10. Alternatively or additionally,intermediate vessels using internals (e.g. trays, loops and/or baffles)are employed.

In one embodiment, the system 1 employs tanks 10, 23 of any size suchthat the height of each tank (i.e. each of tanks 10 and 23, and tank 30of FIG. 6) in the process is equal. In one embodiment, tank 23 is a 1000bbl tank (for oil sweetening) and tank 10 is a 400 bbl tank (for watersweetening) and vice versa, such that each tank are of the same height,or of heights that allowed the levels required in each tank to bemaintained. Tanks 10, 23, 30 may comprise upright cylindrical tanks,horizontal cylindrical tanks, spherical tanks and any manner ofrectangular tank(s) and those known to one skilled in the art. In oneembodiment, one or more of tanks 10, 23, 30 are commercially availabletanks as typically used in the hydrocarbon industry, comprising a 400bbl, nominally 12′×20′, upright cylindrical tank. In one embodiment,tanks 10, 23, 30 are any tanks capable of holding liquid and sealablewith standard 4 oz or 8 oz pressure and vacuum hatches. (These areuniversally called “atmospheric vessels” in that they are made towithstand the hydrostatic weight of liquids and also a slight pressureor vacuum at the top, i.e. a vapor space.) In one embodiment, one ormore of tanks 10, 23, 30 comprise any tank constructed and rated formore pressure and/or vacuum.

In one embodiment, the system 1 operates at substantially atmosphericpressure. It has been found that operating system 1 above nominallyatmospheric pressure, in some configurations or embodiments, inhibitsthe transfer of H₂S.

In certain embodiments, the system 1 is a hybrid system in that itincludes fluids other than water and crude oil. In one embodiment, themethod may use a small amount of liquid surfactant, such as varioustypes of alcohol. Any small amount (1 gallon or less per 300 bbls ofwater used) of liquid surfactant that is known to “water-wet”microscopic solids is employed. Although the liquid surfactant is notrequired, the use of a liquid surfactant allows re-use of the same watercontinuously, nominally indefinitely, without accumulating oil-wetmicroscopic solids on the oil/water interface in the oil sweeteningtank. Such potential solids, if allowed to accumulate at that interface,may inhibit H₂S transfer from rich-oil to lean-water. In one embodiment,less than one (1) gallon of household-grade Isopropyl Alcohol (rubbingalcohol) is employed, and/or ethanol and methanol. Commercial productsknown to “water wet” microscopic solids may additionally oralternatively be used. Such additives are added when needed, asdetermined by sampling the oil-water interface in the oil sweeteningtank with a “tank thief” or any other device capable of obtaining arepresentative sample of that interface (the sample being equal partscrude oil and water.) Also, simple visual inspection will indicatewhether microscopic solids have collected on the interface and thus maymotivate a need for such additives. In one embodiment, volumes ofapproximately between one (1) and two (2) quarts of additive areemployed.

In certain embodiments, scavengers may be used, to, for example,minimize processing time of one or both of the processing of sour oil tosweetened oil and sour water to sweet water. In particular, to minimizeprocess slow-down during the approximately last 10-20% of processingduration (where processing duration is time to convert sour oil to adefined level of sweetened oil and/or duration of time to convert sourwater to a defined level of sweet water), a scavenger may be used. Insuch embodiments, a small amount of H₂S scavenger liquid is provided toone or both of tank 10 and tank 23. The use of scavengers must be,however, balanced against a possible increase in PH level with somescavengers.

In certain embodiments, chemicals that readily capture H₂S, ascommercially available, are added to the method to, for example,increase method efficiencies such as reducing processing durations.

In certain embodiments, the method provides a chemical-free sweeteningprocess that treats sour water for reuse in well servicing, productiondevices and/or for disposal. In certain embodiments, the method removesH2S without introducing any chemicals into the production (e.g. from thewell head) thereby leaving no converted sulphides after treatment. Incertain embodiments, the method prevents or retards or mitigateschemical overtreatment or under-treatment in sweetening operations. Incertain embodiments, the method removes hydrogen sulfide (H2S) from souroil, sour water, sour water/sour oil condensate and/or condensate. Incertain embodiments, the method takes treated (i.e. sweetened) water andapplies the treated water to the production site, e.g. for use in theproduction well e.g. for fracking. In certain embodiments, the methodprevents or reduces or mitigates cross-contamination of wells and/orproduction site. In certain embodiments, the method may handle highconcentrations of H2S and/or low concentrations of H2S. In certainembodiments, the sweetened water produced is transported to storagetanks and/or placed back online.

In certain embodiments, PH modifiers are employed. In some embodiments,the system and/or method (throughout this disclosure, any reference tothe system of the invention also applies to the method and/or process,and vice versa) operates at a PH at or below 7. In some embodiments, thesystem operates at a PH between 1 and 7. In some embodiments, to modifythe water PH downward, various acids or other low-PH materials may beused. Care should be taken to use acidic additives of such low strengthper volume that they do not endanger humans or property or theenvironment in their transportation and use. Acidic additives maycomprise low strength hydrochloric acid, vinegar and lemon juice, andany acidic additives known to those skilled in the art.

In certain embodiments, salts may be added. Generally, in someembodiments, water with various heavier salt(s) content is beneficial tothe process in that salts provide a cleaner oil/water interface in theoil sweetening tank. In some embodiments, the method may use watercomprising fresh water, salt water and any water type wherein the oilbeing sweetened may float upon it. Generally, in some embodiments, thesystem employs water from the same formation(s) and wells from which theoil being treated originates; such water has been found in someembodiments to optimize (e.g. increase efficiencies such as reducingprocessing times) the process.

In certain embodiments, the method operates at ambient temperature. Inother embodiments, warmer (than ambient) temperatures are used, which toa threshold limit, sweetens faster, although causes more hydrocarbonvapors to be vented from the oil sweetening tank. Any gaseous componentventing from the oil sweetening tank, by definition, lowers the volumeof that oil. For this reason, an optimal water temperature range isdecided upon weighing shortening of treating times against oil volumeloss. In winter in cold climates, water may need to be heated prior toprocess start in order to insure that the water used doesn't freezebefore the process is finished. In one embodiment, anti-freeze chemicalcomponents (other than various salts) may be added to the water.

In certain embodiments, the water sweetening tank 10 and the oilsweetening tank 23 (or the levels on each side of partition 32 of singlevessel 30 configuration of FIG. 6) are not at the same level, i.e. notsharing a common bottom plane so as to allow use of hydrostatic pressure(aka gravity feed or gravity equalization) to send the now-H₂S-richwater from the oil sweetening tank back to the water sweetening tank asdepicted in FIG. 1. In such embodiments, additional pumps or similarmeans are employed to pump or move fluid that otherwise was moved viahydrostatic pressure and automated leveling controls are employed on thetank(s) involved. In such embodiments, tank geometries, such as heightand width would not need to be equal.

In certain embodiments, no automation is used, e.g. to control pumpingvolumes and/or tank relative or absolute heights. In certainembodiments, with proper sizing of pump(s), the entire method couldoperate manually without any form of automation or controls.

In certain embodiments, tanks 10, 23, 30 comprise any tank or pressurevessel that at minimum may hold atmospheric pressure and/or theassociated hydrostatic head (and any dynamic loading of the fluidcontainer within) of the contained fluid. Vessels of higher pressurerating may also be used, as well as rail tank cars and sea-bornecontainment vessels.

In certain embodiments, no steam is used. In some embodiments, the waterused is not heated or provided above 110 degree Fahrenheit. In someembodiments, the water is initially supplied at higher temperature (e.g.to a maximum of 110 degree F.) in very cold outside temperatures so asto provide a nominal minimal temperature (e.g. 60 degree F.) for theduration of the sweetening process. FIG. 6 depicts certain embodimentsof the invention that use a common containment vessel. Single vessel 30comprises partition 32 and aperture 34. Partition separates sour watertank 10 from sour oil tank 23. Such a single vessel 30 would generallyreplace separate tanks 10 and 23 of earlier embodiments, e.g. that ofFIG. 1, and engage with other components of system 1 such as line 21supplying water from tank portion 10 to tank portion 23. Stated anotherway, all other lines, pumps, compressors or blowers and line entrypoints into sides of the vessel would be similar or identical to thosein the two-tank system (e.g. of FIG. 1), but with added care to be sureno air introduced into the water sweetening side gets into the pump linegoing to the oil sweetening side. In one configuration, the aperture 34is a slot at the bottom of the barrier or partition 32, although otherconfigurations are possible, to include circular apertures or anyconfiguration that enables a water rate powered by gravity (weight,hydrostatic pressure) to comfortably exceed that which is pumped intothat side of the vessel as H2S-lean water and that prevents air from thewater side into the oil side. Note that the line 22 (of FIG. 1), whichin above configurations (ie those with two physically separate tanks)sends H2S-rich water from the bottom of the oil sweetening tank to thewater sweetening tank, would be fully replaced by the opening (aperture34) in the bottom of the partition 32.

In certain embodiments, the system employs large loops of large diameterpipe instead of tanks.

In certain embodiments, the system employs a non-contained water sourcesuch as a lake, ocean, or river, a water well or any source of non-H2Swater. In one embodiment, the system disposes of H2S-rich water down asour water disposal well.

FIG. 7 depicts alternate embodiments of air injection (aka the air line)into sour water tank 10. Generally, one or more pipes or tubes may entervessel or tank 10, each capped with cap assembly element 12, so as todeliver air via element 14. As such, the air dispenser bar 14 mayterminate in a straight pipe run, or an elbow run, as depicted in FIG.7. The terminus of the air line (i.e. element 14) may be required to beat or below a threshold depth height h from the surface of the water,such as, in a preferred embodiment, at or greater than 0.5 feet, in amore preferred embodiment, at or greater than 1 foot. In someembodiments, the air line enters the tank 10 at any point on the top,bottom or sides of the tank. Note that an air line that enters the tankat the top and then releasing air fairly shallow into the water columnallows a lower pressure blower or compressor to be used to provide theair; this is because if that air line comes in at the bottom, even if itterminates and releases air 6 inches beneath the surface, it can fillwith water between batches, thereby requiring the compressor or blowerto overcome the full hydrostatic weight of the water column in order tostart injecting air.

In certain embodiments, the air line may be equipped with flapper-typecheck valves. In certain embodiments, the air line may terminate insidethe tank (the point where the air is injected into the water) openended, or with a “disperser” consisting of a number of holes. If thereis a disperser, the sum of the area of the holes may equal or exceed thearea of the same line (pipe, hose) open ended. If open ended, the linemay terminate in a downward direction. If a disperser end is used, thatcan be oriented in any way convenient—up, down, horizontally. In certainembodiments, the air line from the compressor or blower may be ofsufficient size as to not create undue back-pressure on the compressoror blower, as this artificial backpressure wastes energy.

In some embodiments, a compressor or blower with a 10-30 standard cubicfeet per minute (SCFM) flow rate will be fitted to a 1.5 inch interiordiameter (ID) air line. In some embodiments, a compressor or blower witha 30-65 standard cubic feet per minute (SCFM) flow rate will be fittedto a 2.0 inch interior diameter (ID) air line. In some embodiments, acompressor or blower with a 65-130 standard cubic feet per minute (SCFM)flow rate will be fitted to a 2.5 inch interior diameter (ID) air line.In some embodiments, the sum of the areas of the holes in any disperserarrangement may meet or exceed the areas of these lines. Generally,larger volumes of air flow, as would be used in greatly scaled upversions of the method, will require the air line from the compressor orblower to be sized such that it does not create undue back-pressure onthe compressor or blower.

In some embodiments, the air may be injected as far from the wateroutlet to the pump as possible. In one embodiment, this may be 180degrees on a circular tank or on the opposite wall on a rectangulartank. If the tank has a longer horizontal dimension, the air injectionpoint and the outlet to the pump may be opposite on or near a linebisecting that longer dimension. Generally, the air should be injectedat a point that minimizes the likelihood that injected air may circulateas bubbles to the line going to the pump. In one embodiment, devices ormethods are employed to prevent air out of the vapor space above the oilin the oil sweetening tank 23, to include using a cavitation vent.

FIG. 8 depicts certain embodiments of the invention as part of anoverall hydrocarbon recovery, processing and transportation system 40. Awell head 42 produces a mixture of hydrocarbon (i.e. sour oil), waterand gas, shown as well head line 43. Well head line 43 enters treator orseparator to separate the oil, water and gas components in any ofseveral known ways. For example, a three-phase separator would separateoil, water and gas, or a 2-phase separator may separate gas from an oiland water emulsion. Such separators are known in the art. In manyseparators 50, gas separated is sent, via separated gas line 52, for gasdistribution 60. Gas distribution 60 may comprise collection, flaring,treating, on-site use for e.g. on-site devices to include vehicles, andstoring/selling. Separator 50 outputs treator/separator line 54comprising sour oil and/or an emulsion of sour oil sour water to system1 of the invention (as described above.) Treator/separator line 54,and/or sweetened oil line 62, may be joined with other sources of souroil and/or emulsions of sour oil sour water, comprising site tank farm44 sources via site tank farm line 45, and off-site tank farm 46 sourcesvia off-site tank farm line 47. Note that line 54 may also return oiland water and/or a water/oil emission to one or both of site tank farm44 and off-site tank farm 46. Also, note that sweetened oil line 62 mayreceive and/or output to one or both of site tank farm line 45 andoff-site tank farm 46. Finally, one or both of site tank farm line 45and off-site tank farm 46, if more broadly used for any manner of liquidstorage, may also interconnect or communicate with other components ofsystem 40, comprising well head 40, treator/separator 50, system 1, andvehicle 70, rail 72, ship 74 and pipeline 76.

System 1 outputs sweetened oil at sweetened oil line 62 and delivers thesweetened oil to one or more recipients, comprising vehicles 70 such assemi-tractor trailers e.g. oil trucks, rail cars 72 or railroad receiversystems, nautical ships or nautical receiver systems 74 and pipelines76.

In certain embodiments, the system 40 comprises “second stageseparators” or “gas boots” which serve to allow additional gas to bereleased from liquids before tankage. For instance, if, for example,element 50 operates at 31 psi, the second stage separator might operateat 16 psi. With some shale production curves falling quickly from 5000BOPD (bbls oil per day) to 800 BOPD, these intermediate vessels allowthe site to operate safely and send less gassy oil totransportation—without the expense of placing a larger or multipletreaters, which cost more than the second stage vessels.

In certain embodiments, the system 40 is scaled so as to be used at a“transload” facility—that is, a pipeline terminal or truck terminalwhich receives oil of all description and blends it, then loads trainswith the oil or sends the oil down other pipelines. One motivation forsuch blending is to lower the H₂S concentration that would otherwiseexist in some batches if not blended with lower H₂S-concentration oil.H₂S concentrations in North Dakota, for instance, are reaching a pointwhere blending might not suffice.

FIG. 9 depicts certain embodiments of a sulfur removal system 80. Theprocess fits or integrates with the above embodiments, e.g. that shownin FIG. 1, by replacing the flare stack. The system 80 receives air fromvapor space as element 15. Dilution (line 24) in system 80 would only beused to create a vacuum on the left side of FIG. 9 to reduceback-pressure on the system. In that the total stream is cooledsignificantly by the time it reaches the left side of FIG. 9, a fanplaced in the pipe a short way from the end may serve better, therebyreducing the size of the compressor or blower in FIG. 1.

The process of FIG. 9 brings the entire air flow on the exhaust end ofthe baseline process (the H2S-rich exhaust coming from the waterstripping tank) up to a temperature between 900 and 1400 degreesFahrenheit. This incineration converts all the H2S to SO2 (sulfurdioxide). Waste heat downstream of incineration is then used to createsteam (in a steam jacket external of the incineration pipe) from a smallamount of fresh water (water new to the system). This steam is injecteda short distance downstream of where it is created, into theincineration pipe. The steam quickly grabs the SO2 (although not theH2S, as there is no H2S left at this stage). The air and SO2-rich steamare then cooled to the point that the steam condenses to water. Statedanother way, the system makes it rain inside the pipe. (Rain is an aptdescription here because it is what is commonly known as “acid rain”,the SO2 having been converted to sulfuric acid in water.) Note that theacid rain is captured and confined, and not releases into theenvironment, as occurs when H2S is flared directly. The acidic water iscollected. The remaining (now sulfur-free or very very sulfur-reduced)air is vented to atmosphere. The acidic water may then be; 1) used inthe previous process to keep the water PH low which is essential forefficiency, or 2) treated with a small amount of soda ash (or otherinexpensive base) and safely disposed of into common, non-sour waterdisposal wells. It should be understood that the drawings are notnecessarily to scale. In certain instances, details that are notnecessary for an understanding of the invention or that render otherdetails difficult to perceive may have been omitted. It should beunderstood, of course, that the invention is not necessarily limited tothe particular embodiments illustrated herein.

These and other advantages will be apparent from the disclosure of theinvention(s) contained herein. The above-described embodiments,objectives, and configurations are neither complete nor exhaustive. Aswill be appreciated, other embodiments of the invention are possibleusing, alone or in combination, one or more of the features set forthabove or described in detail below. Further, this Summary is neitherintended nor should it be construed as being representative of the fullextent and scope of the present invention. The present invention is setforth in various levels of detail in this Summary, as well as in theattached drawings and the detailed description below, and no limitationas to the scope of the present invention is intended to either theinclusion or non-inclusion of elements, components, etc. in thisSummary. Additional aspects of the present invention will become morereadily apparent from the detailed description, particularly when takentogether with the drawings, and the exemplary claim provided herein.

EXAMPLES Example 1

To determine tons of sulfur emitted using one embodiment of theinvention, a water tank was filled with approximately 350 barrels ofsour water, the sour water having a concentration of 10,000 (1%)hydrogen sulfide, as tested through a bottle test described in Example2, below. Air from an air compressor was distributed into the bottom ofthe tank at a steady rate of 105 scfm. The air from the vapor space inthe tank was then transferred to a vent stack. The amount of hydrogensulfide and sulfur in the vent stack was measured over a twelve hourperiod. The measurements were taken around every thirty minutes. The airin the vent stack measured 11.25 scf hydrogen sulfide and 1.01 ofsulfur. The airflow into the water tank was kept at a steady 105 scfmand recorded the concentration over time in the vented air. This wasapproximately 350 barrels of 1% hydrogen sulfide (in tank vapor spacetested via bottle test) water. Although air flow was regulated manuallyin this example, certain aspects of the process could be automated. Forexample, a PID loop and splitter valve configuration could be used.

Example 2

To determine the amount of hydrogen sulfide present in materialssubjected to treatment through certain embodiments of the invention, a“bottle test” was conducted. The bottle test comprises filling acontainer with 50% of the liquid to be tested, drilling a hole in thetop of the container, agitating the container for at least thirtyseconds, and measuring the amount of hydrogen sulfide in the vapor spacewith a hydrogen sulfide meter. In this example, a 1000 ml container wasused, but the size of the container is for illustrative purposes only.The 1000 ml container was filled with 500 ml of the liquid to be tested,whether oil or water. A small hole was drilled into the lid of thecontainer. The hole at the top of the container was covered. Thecontainer was then agitated by shaking the container for at least 30seconds. A longer agitation time did not affect the results. Afteragitation, the vapor space was measured for the amount of hydrogensulfide. The hydrogen sulfide can be measured with a plunger-type,electronic or similar hydrogen sulfide meters. A bottle test wasconducted prior to removing hydrogen sulfide according to the presentinvention, after removing hydrogen sulfide according to the presentinvention, and prior to loading the water and/or oil in a truck fortransportation. However, a bottle test is not performed if there is anymeasurable hydrogen sulfide in the air to be vented, as hydrogen sulfidewill continue to be removed through the described invention until theconcentration of hydrogen sulfide is below the acceptable limits.Acceptable limits can include the levels of hydrogen sulfide allowed bythe EPA to be released into the environment, safety limits set by OSHA,and/or other relevant regulations.

After subjecting sour water or sour oil to treatment with the presentinvention, it was found that the water or oil, when bottle tested, had areading below 3 ppm hydrogen sulfide in the vapor space, and the liquidsthemselves had almost no hydrogen sulfide either when tested withhydrogen sulfide test strips.

Example 3

Oil from Little Knife Field in North Dakota contained both hydrogensulfide and sulfur. The pre-process hydrogen sulfide in the vapor spacemeasured at 10.6% or 106,000 ppm. Using a sulfur-in-crude analyzer, thepre-process sulfur by weight measured at 0.66%. After treatment with thepresent invention, both hydrogen sulfide and sulfur by weight contentwas reduced, where hydrogen sulfide was reduced to 0% or less than 1 ppmand the process reduced the sulfur by weight to 0.55% by weight.

Example 4

Oil from Whitney Canyon Field in Wyoming contained both hydrogen sulfideand sulfur. The pre-process hydrogen sulfide in the vapor space measuredat 17.4% or 174,000 ppm. Using a sulfur-in-crude analyzer, thepre-process sulfur by weight measured at 0.84%. After treatment with thepresent invention, both hydrogen sulfide and sulfur by weight wasreduced, where hydrogen sulfide was reduced to 0% or less than 1 ppm andthe sulfur by weight was reduced to 0.51% by weight.

1. A method for removing hydrogen sulfide from crude oil and watercomprising: filling a first container with water; filling a secondcontainer with crude oil and water, wherein the crude oil compriseshydrogen sulfide; distributing air in a first stream from a device thatcan create airflow to the first container, using a first connectionrunning from the device to the first container, wherein the terminal endof the first connection comprises at least one opening; collecting airin a vapor space located within the first container, the collected aircomprising hydrogen sulfide; transferring the collected air from thevapor space through an enclosed connection to an air compartment;distributing air in a second stream from the device to the aircompartment using a second connection running from the device to the aircompartment; mixing the second stream and the collected air to form anair mixture; removing the air mixture from the air compartment when theamount of hydrogen sulfide measured is below a desired amount;distributing water from the first container to the second container viaa pumping means; measuring the amount of hydrogen sulfide in the crudeoil within the second container; continuing to distribute water from thefirst container to the second container until the amount of hydrogensulfide in the crude oil in the second container is below a desiredamount; returning water from the second container to the firstcontainer; continuing to distribute air in the second stream from thedevice to the first container; continuing to transfer air from the vaporspace from the air compartment; and continuing to measure the amount ofhydrogen sulfide in the air mixture wherein the air mixture is removedwhen the amount of hydrogen sulfide measured is below a desired amount.2. The method of claim 1 wherein the water is fresh water.
 3. The methodof claim 1, wherein the removed air is released to the atmosphere. 4.The method of claim 1, wherein the removed air is flared.
 5. The methodof claim 1, wherein when the amount of hydrogen sulfide in the crude oilin the second storage device is below a desired amount, transferring thecrude oil.
 6. The method of claim 5, wherein the crude oil istransferred to at least one of a vehicle, a rail car and a ship.
 7. Themethod of claim 1, further comprising maintaining the pH of said waterat 7.0 or below.
 8. The method of claim 1, wherein the removed air isstored.
 9. The method of claim 1, wherein the water distributed from thefirst container to the second container is distributed at an upperportion of the second container.
 10. A method for removing hydrogensulfide from an emulsion of water and crude oil, comprising: receiving,from a well production site, a well production stream comprising sourgas and sour crude oil; separating the well production stream into atleast sour gas and an emulsion of sour water and sour oil, wherein theemulsion comprises hydrogen sulfide; treating the emulsion to remove atleast a substantial portion of the hydrogen sulfide, the treatingcomprising: filling a first storage device with water; filling a secondstorage device with the emulsion; distributing air in a first streamfrom a device that can create airflow to the first container, using afirst connection running from the device to the first container, whereinthe terminal end of the first connection comprises at least one opening;collecting air in a vapor space located within the first container, thecollected air comprising hydrogen sulfide; transferring the collectedair from the vapor space through an enclosed connection to an aircompartment; distributing air in a second stream from the device to theair compartment using a second connection running from the device thatcan create airflow to the air compartment; mixing the second stream andthe collected air to form an air mixture; removing the air mixture fromthe air compartment when the amount of hydrogen sulfide measured isbelow a desired amount; distributing water from the first container tothe second container via a pumping means; measuring the amount ofhydrogen sulfide in the crude oil within the second container;continuing to distribute water from the first container to the secondcontainer until the amount of hydrogen sulfide in the crude oil in thesecond container is below a desired amount; returning water from thesecond container to the first container; continuing to distribute air inthe second stream from the device to the first container; continuing totransfer air from the vapor space from the air compartment; andcontinuing to measure the amount of hydrogen sulfide in the air mixturewherein the air mixture is removed when the amount of hydrogen sulfidemeasured is below a desired amount.
 11. The method of claim 10, whereinthe water is fresh water.
 12. The method of claim 10, wherein the wateris fresh water.
 13. The method of claim 10, wherein the removed air isreleased to the atmosphere.
 14. The method of claim 10, wherein theremoved air is flared.
 15. The method of claim 10, wherein the removedair is stored.
 16. The method of claim 10, wherein when the amount ofhydrogen sulfide in the crude oil in said second storage device is belowa desired amount, transferring the crude oil.
 17. The method of claim16, wherein the crude oil is transferred to at least one of a vehicle, arail car and a ship.
 18. A method for removing hydrogen sulfide fromsour water comprising: receiving a stream of sour water, the sour watercomprising hydrogen sulfide; filling a first container with water;distributing air in a first stream from a device that can create airflowto the first container, using a first connection running from the deviceto the first container, wherein the terminal end of the first connectioncomprises at least one opening; collecting air in a vapor space locatedwithin the first container, the collected air comprising hydrogensulfide; transferring the collected air from the vapor space through anenclosed connection to an air compartment; distributing air in a secondstream from the device to the air compartment using a second connectionrunning from the device to the air compartment; mixing the second streamand the collected air to form an air mixture; removing the air mixturefrom the air compartment when the amount of hydrogen sulfide measured isbelow a desired amount; continuing to distribute air in the secondstream from the device to the first container; continuing to transferair from the vapor space from the air compartment; and continuing tomeasure the amount of hydrogen sulfide in the air mixture wherein theair mixture is removed when the amount of hydrogen sulfide measured isbelow a desired amount.
 19. The method of claim 18, wherein the streamof sour water is received from a well production site.
 20. The method ofclaim 19, wherein the removed air is at least one of flared, stored andreleased to the atmosphere.